|Publication number||US7920976 B2|
|Application number||US 12/055,503|
|Publication date||Apr 5, 2011|
|Filing date||Mar 26, 2008|
|Priority date||Mar 27, 2007|
|Also published as||US8244489, US8489346, US8587949, US20080238713, US20080243404, US20110184674, US20120303299, US20150120230|
|Publication number||055503, 12055503, US 7920976 B2, US 7920976B2, US-B2-7920976, US7920976 B2, US7920976B2|
|Original Assignee||Electro Industries / Gauge Tech.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (34), Referenced by (4), Classifications (17), Legal Events (2)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application is based on and claims priority to U.S. Provisional Patent Application No. 60/920,198, filed on Mar. 27, 2007, which is hereby expressly incorporated by reference herein.
The present patent relates generally to the field of intelligent electronic devices for electrical utility services and, more specifically, to digital electrical power and energy meters for use in performing electrical utility services.
Producers, suppliers, and consumers of electrical power rely on energy meters to monitor power consumption and quality for numerous purposes, including billing, revenue, distribution, and process management. Traditionally, the primary means of measuring power consumption was an electro-mechanical power meter, while a number of other types of meters and equipment measured other parameters of power generation, distribution, usage, and quality. As technology has improved, intelligent electronic devices (IEDs), such as digital power and energy meters, Programmable Logic Controllers (PLCs), electronically-controlled Remote Terminal Units (RTUs), protective relays, fault recorders, and the like, have slowly replaced their electro-mechanical and analog counterparts.
The shift to IEDs from analog and electro-mechanical devices provides a vast array of advantages including improvements in measurement accuracy (e.g., voltage, current, power consumption, power quality, etc.) and system control (e.g., allowing a meter to trip a relay or circuit breaker). However, as a result of the increased sensitivity brought about by recent advances in technology and, in general, the shift to electronic meters from their analog counterparts, measurement accuracy tends to suffer as a result of low-amplitude and/or high-frequency noise on the signals measured.
An improved intelligent electronic device, e.g., a digital electrical power and energy meter, that is less susceptible to low-amplitude and/or high frequency noise on a measured signal or parameter operates to average the measured signal or parameter over a number of consecutive cycles of the measured signal or measured parameter to produce an averaged signal, which minimizes the effect on measurement accuracy of the noise in any particular cycle of the signal. In one embodiment, a digital electrical power and energy meter includes a metering module that detects one or more parameters of an AC electrical service. Moreover, the digital electrical power and energy meter includes a processing module that processes data obtained using the metering module, wherein the processing module combines (e.g., averages) a plurality of values of at least one of the one or more parameters from a number of cycles (e.g., consecutive or non-consecutive cycles) of the AC signal. If desired, the processing module may process a first value, x1, of at least one parameter, the first value obtained at a time, t1, of a first AC cycle having a period p and may process one or more additional values, x2 through xi, of the at least one parameter, each of the one or more additional values obtained at a time t=t1+(n×p), corresponding to one or more later AC cycles having the period p, wherein i is a pre-determined number and n is a number between 1 and i.
To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures, except that suffixes may be added, when appropriate, to differentiate such elements. The images in the drawings are simplified for illustrative purposes and are not depicted to scale.
The appended drawings illustrate exemplary embodiments of the present disclosure and, as such, should not be considered as limiting the scope of the disclosure that may admit to other equally effective embodiments. It is contemplated that features or steps of one embodiment may beneficially be incorporated in other embodiments without further recitation.
While the figures and description herein are specifically directed to digital electrical power and energy meters, the concepts disclosed herein may also be applied in the context of other types of Intelligent Electronic Devices (IEDs) including, for example, Programmable Logic Controllers (PLCs), Remote Terminal Units (RTUs), protective relays, fault recorders, and other devices or systems used to quantify, manage, and control quality, distribution, and consumption of electrical power. Thus, as used herein, the term “digital electrical power and energy meter” refers broadly to any IED adapted to record, measure, communicate, or act in response to one or more parameters of an electrical service. These parameters may include, for example, supply currents and supply voltages, their waveforms, harmonics, transients, and other disturbances, and other corresponding parameters, such as power, power quality, energy, revenue, and the like. Moreover, a variety of electrical service environments may employ IEDs and, in particular, may employ digital electrical power and energy meters. By way of example and not limitation, these environments include power generation facilities (e.g., hydroelectric plants, nuclear power plants, etc.), power distribution networks and facilities, industrial process environments (e.g., factories, refineries, etc.), and backup generation facilities (e.g., backup generators for a hospital, a factory, etc.).
A processing module 120 within the meter 100 facilitates operation and administration of the meter 100 and processes data obtained from the metering module 110 via an interface 123. A user interface module 130 includes a user display 132 that displays results of measurements and calculations and allows configuration of the meter 100. The user interface module 130 also includes a plurality of indicators 134 and a plurality of user controls 136 which will be described in more detail below. Additionally, the user interface module 130 may include an energy pulse such as an infra-red or KYZ pulse 155. The infra-red or KYZ pulse 155 is coupled to the metering module 110, and provides an indication of energy consumption by outputting a pulse in proportion to accumulated energy consumption. An interface 129 couples the user display 132 to the processing module 120, while an interface 127 couples the user controls 136 to the processing module 120. Moreover, a communications module 135 includes a network communication card 142 and an infra-red (IR) communication device 146 and operates to facilitate communication of data to one or more external devices (not shown). The communication module 135 operates to couple the meter 100 to one or more remote terminals (not shown), and/or allows remote configuration of the meter 100. As illustrated in
While some of the metering module 110, the processing module 120, and the power supply 150 may be required for meter operation, other modules in the illustrated embodiment are optional and may be omitted or replaced with different modules. Each of the modules 110, 130, 135, 140, and 150 is coupled to the processing module 120 and the power supply 150 is coupled to each of the modules 110, 120, 130, 135, and 140. Typically, the power supply 150 is operatively connected to the other modules of the meter 100 via a plurality of traces in the printed circuit boards (PCBs) within the meter 100. The power supply 150 is also communicatively coupled to a source of power. For example, the power supply 150 may be coupled to an external or auxiliary power source 152 via a connection 151. Alternatively, the power supply 150 may be coupled directly to the electrical service 101 via a connection 153 and obtain the source of power from the electrical service 101.
Referring now to
As illustrated in
In the embodiment depicted in
The processor 160 may additionally include circuitry 163 and 165 for implementing gain control on the additional voltage and current signal channels coming from the sensing module 115 as part of the interface 123 and converting the analog signals representative of the sensed currents and voltages to digital signals (e.g., using one or more ADCs). The processor 160 may use the additional channels, each of which includes a voltage signal and a current signal for each phase of the electrical service 101, and the corresponding circuitry 163 and 165 for metering tasks that require different gain factors than the gain factors used in the energy metering functions executed on the metering module 110 to fully utilize the dynamic range of the corresponding ADC. In particular, the processor 160 may use one additional signal channel to provide waveform capture functionality. In contrast to calculating energy consumption (or generation), waveform capture must have a much larger dynamic range to capture transients such as voltage spikes (which may exceed the nominal voltage of the system by orders of magnitude). The processor 160 may use another additional voltage signal channel and current signal channel for calculating harmonic effects in the electrical service, as capturing this information requires yet a different dynamic range, and thus a different gain setting and/or different filtering.
Monitored signals, such as voltage and current, and parameters (e.g., power) calculated from the monitored signals, are subject to errors due to noise on the signals. Noise may be the result of various phenomena, including the equipment or other loads on the electrical service 101, power generation equipment, nearby electromagnetic radiation, or even components (such as the power supply 150) within the meter 100. Of course, this signal noise may decrease the accuracy of measurements and calculations of the various parameters monitored and calculated by the meter 100. Taking an average of the signal over several cycles is one way to mitigate the effects of the signal noise on the parameter measurements.
One embodiment uses multi-cycle averaging to negate the effects of noise on the voltage and current signals when calculating total harmonic distortion (THD). The meter 100 calculates THD using the voltage and current signals of one of the analog channels between the sensing module 115 and the processor 160 and present on the interface 123 (i.e., one of the channels to the Gain/ADC circuitry 163 or 165). Each of the current and voltage signals is input into one or more ADCs in the circuitry 163 (or the circuitry 165). The ADCs sample the signals at a known frequency, thereby converting the analog signals into a series of measurements, represented by digital values.
In a step 214, the processor 160 (or other processor, such as the metering processor 118) determines the samples from different cycles but corresponding to the same phase angles of the time-varying signal 205. For example, in
The processor 160 performs step 214 for some number M of the samples accumulated for each cycle, depending on the required resolution of the signal and the required accuracy of the measurements or calculations. For example, in
In a step 216, the processor 160 averages, for a pre-determined number of consecutive cycles (or, alternatively for a pre-determined time interval), the values of the correlated samples determined in the step 214. If, for example, the pre-determined number of consecutive cycles over which the M samples in each cycle are averaged is N cycles, the processor 160 calculates the average for each set of N samples (one set for each of the M samples taken per cycle) having the same phase angle. This calculation may be expressed as:
where X is a number between 1 and M corresponding to a sample at a given phase angle, AVGX is the average of values corresponding to phase angle X across N cycles, and S is a value between 1 and N indicative of the cycle from which the value was measured (e.g., S1 is a sample from the first cycle, S2 is a sample from the second cycle with a similar phase angle as the sample from the first cycle, and so on to the sample from the Nth cycle, SN). Of course, the step 216 yields a set of values AVG1 through AVGM, each of which is a value defining the average over N cycles of the signal 205 at a particular phase angle. The accumulation of the values AVG1 through AVGM represents a single-cycle waveform that is the average of the N cycles. For example, this process, when applied to the signal 205 of
In a step 218, the averages determined by the step 216 (i.e., AVG1-AVG16) are used to calculate a parameter. For example, in the preferred embodiment, the step 218 calculates the Total Harmonic Distortion (THD) of the signal by performing a fast Fourier transform (FFT), utilizing the average values of the sampled waveform. Of course, other parameters could be calculated as well as or instead of using the average waveform. For example, the calculated parameters may be a magnitude value or a root mean square value of any of a line voltage, a line current, a phase voltage, and a phase current. Likewise, if desired, the calculated parameter may be a real power, a reactive power, a total power and/or a power factor or any other desired parameter.
Of course, it is not required that every sample be included in the averaging process. For example, one embodiment may collect data over eight consecutive cycles, using a sampling rate of 256 samples/cycle and thereby collect 2048 samples (256 samples/cycle over 8 cycles). However, the average values for the eight consecutive cycles may be computed using only every eighth sample of each cycle. Thus, in this embodiment, while the signal is sampled 2048 times, only 256 of the 2048 samples are used in the average (e.g., samples 1, 8, 16, . . . 256 of each cycle, for each of the eight cycles). The end result is a waveform comprising 32 points (e.g., AVG1, AVG8, AVG16, . . . , AVG256) that represents the average waveform of the 8 cycles. The averaging process may be repeated for each channel (e.g., each current phase and each voltage phase) if so desired. Naturally, the resolution of the average waveform (i.e., the waveform formed from the calculated average values) may be varied by using more of the samples (e.g., using every fourth sample instead of every eighth sample per cycle) and/or sampling at a higher frequency (e.g., sampling at 2048 samples/cycle instead of 256 samples/cycle).
The method described above, while applicable to a variety of parameters (e.g., current, voltage, energy, real power, etc.), is particularly useful in calculating the Total Harmonic Distortion of a signal by performing a fast Fourier transform (FFT), utilizing the average values of the sampled waveform. This is true because the THD is a relatively static parameter, and noise on the signal or signals is likely spurious in nature or introduced in the analog-to-digital converter. Thus, by removing the noise using the method described above (or another averaging method), the calculated THD more accurately reflects THD of the signals on the electrical service 101.
While the method 210 uses averages to mitigate the effects of noise on the calculation of a parameter monitored by the meter 100, the meter 100 may also employ a method 220, illustrated in
The method 220 of
Having collected M consecutive values of parameter P in step 222, the processor 160 calculates the average F of the M values of parameter P in step 224. While there are a variety of averaging techniques that could be implemented by the method 220 or similar methods, the averaging technique employed by the method 220 may be expressed as:
Upon receiving the next consecutive value of the parameter P (i.e., PM+1), the processor 160 may calculate a weighted average F′ in a step 226, using the equation:
In a step 228, the processor 160 calculates the absolute value of the difference between the weighted average F′ and the value of the last consecutive measurement of parameter P (i.e., PM+1), and compares this difference to a pre-determined value A. This computation may be expressed as:
|F′−P M+1 |≦A
If the equation above evaluates to be true (e.g., if the magnitude of the difference is less than the threshold A), a step 232 displays the value F′. The time intervals 256, 258, and 260 of
A user of, or, in the one embodiment, the manufacturer of the meter 100 sets the pre-determined threshold value A according to the type and characteristics of the signal to which the method 220 is being applied, and according to the type and likelihood of noise on the affected signal. For example, when determining the threshold value A for a signal or parameter for which relatively small changes in the value of the parameter are indicative of more than simple noise, A should be set to a relatively smaller number. By contrast, when determining the threshold value A for a signal or parameter for which noise is likely to be of a higher amplitude, the pre-determined value A should be set to a relatively larger number, such that transient noise does not adversely affect the measurements related to the signal or parameter. Of course, the value A may be different for each parameter or signal, and may vary even on a single signal according to, for example, the scaling of the measurement.
Although the disclosure herein has been described with reference to particular illustrative embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the present disclosure. Therefore, numerous modifications may be made to the illustrative embodiments and other arrangements may be devised without departing from the spirit and scope of the present disclosure, which is defined by the appended claims.
Furthermore, although the foregoing text sets forth a detailed description of numerous embodiments, it should be understood that the legal scope of the present disclosure is defined by the words of the claims set forth at the end of this patent. The detailed description is to be construed as exemplary only and does not describe every possible embodiment, as describing every possible embodiment would be impractical, if not impossible. One could implement numerous alternate embodiments, using either current technology or technology developed after the filing date of this patent, which would still fall within the scope of the claims.
It should also be understood that, unless a term is expressly defined in this patent using the sentence “As used herein, the term ‘______’ is hereby defined to mean . . . ” or a similar sentence, there is no intent to limit the meaning of that term, either expressly or by implication, beyond its plain or ordinary meaning, and such term should not be interpreted to be limited in scope based on any statement made in any section of this patent (other than the language of the claims). To the extent that any term recited in the claims at the end of this patent is referred to in this patent in a manner consistent with a single meaning, that is done for sake of clarity only so as to not confuse the reader, and it is not intended that such claim term be limited, by implication or otherwise, to that single meaning. Finally, unless a claim element is defined by reciting the word “means” and a function without the recital of any structure, it is not intended that the scope of any claim element be interpreted based on the application of 35 U.S.C. §112, sixth paragraph.
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|U.S. Classification||702/60, 361/97, 700/293, 702/58, 700/292, 361/94, 324/76.39, 361/196, 702/72|
|Cooperative Classification||H05K7/1424, G01R35/00, G01R22/06, G01R21/00, G01R22/065|
|European Classification||H05K7/14F5, G01R22/06D2|
|Mar 26, 2008||AS||Assignment|
Owner name: ELECTRO INDUSTRIES/GAUGE TECH., NEW YORK
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:BANHEGYESI, TIBOR;REEL/FRAME:020703/0027
Effective date: 20080319
|Sep 16, 2014||FPAY||Fee payment|
Year of fee payment: 4